Method for converting hydrocarbon feedstock comprising a shale oil by hydroconversion in an ebullating bed, fractionation by atmospheric distillation and hydrocracking

ABSTRACT

Method and plant for converting hydrocarbon feedstock comprising a shale oil, comprising a step of hydroconverting in an ebullating bed, a fractionation into a light fraction, a naphtha fraction, a gas-oil fraction and a fraction heavier than gas-oil, the naphtha and gas oil fraction being hydrotreated, the fraction heavier than gas oil being hydrocracked, the products of the hydrocracking being sent to the step for hydrotreating. The method aims to maximize the yield of fuel bases.

The invention relates to a method for converting hydrocarbon feedstocks comprising a shale oil into lighter products which can be utilized as fuels and/or raw materials for petrochemistry. The invention relates more particularly to a method for converting hydrocarbon feedstocks comprising a shale oil that comprises a step of hydroconverting the feedstock in an ebullating bed, followed by a step of fractionating by atmospheric distillation to give a light fraction, naphtha fraction and gas-oil fraction and to give a fraction heavier than the gas-oil fraction, a dedicated hydrotreating for each of the naphtha and gas-oil fractions, and a hydrocracking of the fraction heavier than the gas-oil fraction. This method enables shale oils to be converted into very-high-quality fuel bases, and is aimed more particularly at an excellent yield.

In view of high barrel price volatility and a reduction in discoveries of conventional petroleum fields, petroleum groups are turning towards non-conventional sources. Next to petroleum-bearing sands and deep offshore, bituminous shales, although relatively poorly known, are becoming ever more coveted.

Bituminous shales are sedimentary rocks which contain an insoluble organic substance called kerogen. By heat treatment in situ or ex situ (“retorting”) in the absence of air at temperatures of between 400 and 500° C., these shales liberate an oil, shale oil, with a general appearance like that of crude petroleum.

Although of a different composition from crude petroleum, shale oils may constitute a substitute for the latter and also a source of chemical intermediates.

Shale oils cannot be directly substituted into the applications of crude petroleum. Indeed, although these oils resemble petroleum in certain respects (for example, in a similar H/C ratio), they differ in their chemical nature and in a much greater level of metallic and/or non-metallic impurities, thereby making the converting of this non-conventional resource much more complex than that of petroleum. Shale oils have, in particular, levels of oxygen and of nitrogen that are much higher than those in petroleum. They may also contain higher concentrations of olefins, of sulphur or of metal compounds (especially compounds containing arsenic).

Shale oils obtained by pyrolysis of kerogen contain a large number of olefinic compounds resulting from cracking, and this translates into additional hydrogen demand at the refining stage. For instance, the bromine index, which enables calculation of the concentration by weight of olefinic hydrocarbons (by addition of bromine to the ethylenic double bond), is generally greater than 30 g/100 g of feedstock for shale oils, whereas it is between 1 and 5 g/100 g of feedstock for residues of petroleum. The olefinic compounds resulting from cracking are essentially composed of monoolefins and diolefins. The unsaturations present in the olefins are a potential source of instability by polymerization and/or oxidation.

The oxygen content is generally higher than in heavy crudes, and may be as much as 8% by weight of the feedstock. The oxygen compounds are often phenols or carboxylic acids. Consequently, shale oils may have a marked acidity.

The sulphur content varies between 0.1% and 6.5% by weight, necessitating stringent desulphurizing treatments in order to meet the specifications for fuel bases. The sulphur compounds are in the form of thiophenes, sulphides or disulphides. Moreover, the sulphur distribution profile within a shale oil may be different from that obtained in a conventional petroleum.

The most distinctive feature of the shale oils, nevertheless, is their high nitrogen content, which makes them unsuitable as a conventional feedstock for the refinery. Petroleum generally contains around 0.2% by weight of nitrogen, whereas crude shale oils contain generally of the order of 1% to approximately 3% by weight or more of nitrogen. Moreover, the nitrogen compounds present in petroleum are generally concentrated in relatively high boiling ranges, whereas the nitrogen of the compounds present in crude shale oils is generally distributed throughout all of the boiling ranges of the material. The nitrogen compounds in petroleum are primarily non-basic compounds, whereas, generally, around half of the nitrogen compounds present in crude shale oils are basic. These basic nitrogen compounds are particularly undesirable in refinery feedstocks, since these compounds often act as catalyst poisons. Furthermore, the stability of the products is a problem which is common to numerous products derived from shale oil. Such instability, including photosensitivity, appears to result essentially from the presence of nitrogen compounds. Consequently, crude shale oils must generally be subjected to a stringent refining treatment (high total pressure) in order to obtain a synthetic crude petroleum or fuel base products which meet the specifications in force.

It is also known that shale oils may contain numerous metal compounds in traces, generally present in the form of organometallic complexes. The metal compounds include the conventional contaminants such as nickel, vanadium, calcium, sodium, lead or iron, but also metal compounds of arsenic. Indeed, shale oils may contain an amount of arsenic of more than 20 ppm, whereas the amount of arsenic in crude petroleum is generally in the ppb (parts per billion) range. All of these metal compounds are catalyst poisons. More particularly, they irreversibly poison the hydrotreating catalysts and hydrogenating catalysts by gradually being deposited on the active surface. The conventional metal compounds and part of the arsenic are found primarily in heavy cuts, and are removed by deposition on the catalyst. On the other hand, when the products containing arsenic are capable of generating volatile compounds, these compounds may be found partly in the lighter cuts and may, as a result, poison the catalysts in subsequent converting processes, during refining or in petrochemistry.

Furthermore, shale oils generally contain sandy sediments originating from bituminous shale fields from which the shale oils are extracted. These sandy sediments may give rise to clogging problems, especially in fixed bed reactors.

Lastly, shale oils contain waxes, which give them a pour point higher than the ambient temperature, thereby preventing their transport in oil pipelines.

In view of appreciable resources, and in view of their evaluation as being a promising source of petroleum, there exists a genuine need for converting shale oils into lighter products which can be utilized as fuels and/or raw materials for petrochemistry. Methods for converting shale oils are known. Conventionally, conversion is practised alternatively by coking, by hydrovisbreaking (thermal cracking in the presence of hydrogen) or by hydroconverting (catalytic hydrogenation). Liquid/liquid extraction processes are also known.

Thus, patent document FR 2197968 describes a process for the filtration and hydrogenation of shale oils or of bituminous sand oils containing particles, comprising the steps that consist in (a) continuously passing said oil into the bottom of a reactor in a mixture with hydrogen, (b) intermittently sending catalyst into the top of the reactor and removing catalyst and entrained particles from the bottom of the reactor to effect a catalyst transfer through the reactor, (c) measuring the pressure drop between the bottom of the reactor and the top of the reactor, and (d) adjusting the catalyst flow rate to correct the pressure drop to a preselected pressure which corresponds to a desired rate of filtration in the reactor. The process described in FR 2197968 is especially silent on the use of independent sections for the hydrotreatment of naphtha and gas oil fractions.

Patent document U.S. Pat. No. 6,153,087 describes a process for converting heavy feedstocks comprising an ebullated-bed conversion and a hydrocracking operation. The process is applied to various heavy feedstocks having an initial boiling point of at least 300° C. The application to shale oils is neither mentioned nor suggested. The use of independent sections for the hydrotreatment of naphtha and gas oil fractions is not envisaged.

OBJECT OF THE INVENTION

The particular feature of shale oils in having a certain number of metallic and/or non-metallic impurities makes it much more complex to convert this non-conventional resource than petroleum. The challenge for the industrial development of methods for converting shale oils is therefore the need to develop methods which are suited to the feedstock, allowing the yield of high-quality fuel bases to be maximized. The conventional refining treatments known from petroleum must therefore be adapted to the specific composition of the shale oils.

The present invention aims to improve the known methods for converting hydrocarbon feedstocks comprising a shale oil by increasing, especially, the yield of fuel bases for a combination of steps having a specific linkage, and a treatment appropriate to each fraction obtained from the shale oils. Likewise, an object of the present invention is to obtain high-quality products having more particularly a low sulphur, nitrogen and arsenic content, preferably meeting the specifications. Another objective is to provide a method which is simple, i.e. having as few steps as necessary, while remaining effective, allowing capital investment costs to be limited.

In its broadest form, and according to a first aspect, the present invention is defined as a method for converting hydrocarbon feedstock comprising at least one shale oil having a nitrogen content of at least 0.1%, often at least 1% and very often at least 2% by weight, characterized in that it comprises the following steps:

a) The feedstock is conveyed into a section for hydroconverting in the presence of hydrogen, said section comprising at least one ebullating bed reactor operating in gas and liquid upflow mode and containing at least one supported hydroconverting catalyst,

b) The effluent obtained in step a) is conveyed at least partly, and often entirely, into a fractionating zone, from which, by atmospheric distillation, a gaseous fraction, a naphtha fraction, a gas-oil fraction and a fraction heavier than gas-oil are recovered,

c) Said naphtha fraction is treated at least partly, and often entirely, in a first section for hydrotreating in the presence of hydrogen, said first section comprising at least one first fixed bed reactor containing at least one first hydrotreating catalyst,

d) Said gas-oil fraction is treated at least partly, and often entirely, in a second section for hydrotreating in the presence of hydrogen, said second section comprising at least one second fixed bed reactor containing at least one second hydrotreating catalyst,

e) The fraction heavier than the gas-oil fraction is treated, at least partly and often entirely, in a section for hydrocracking in the presence of hydrogen.

The hydroconversion section in step a) typically comprises from one to three, and preferably two, reactors in series, and the first and second hydroconversion sections in steps c) and d) comprises independently from each other from one to three reactors in series.

The research work carried out by the applicants into the conversion of shale oils has led to the finding that an improvement to the existing methods, in terms of yield of fuel bases and in terms of product purity, is possible through a combination of various steps linked in a specific way. Each fraction obtained by the method according to the invention is subsequently conveyed to a treating section.

In a first time, the hydrocarbon feedstock comprising the shale oil is subjected to a hydroconversion in an ebullating bed. The technology of the ebullating bed, relative to the technology of the fixed bed, enables the treatment of feedstocks which are heavily contaminated with metals, heteroatoms and sediments, such as the shale oils, while exhibiting conversion rates which are generally greater than 50%. Indeed, in this first step, the shale oil is converted into molecules which enable the generation of future fuel bases. The majority of the metallic compounds, of the sediments and of the heterocyclic compounds is removed. The effluent emerging from the ebullating bed therefore contains the most resistant nitrogen and sulphur compounds, and possibly volatile arsenic compounds which are present in lighter components.

The effluent obtained in the hydroconverting step is subsequently fractionated by atmospheric distillation, producing various fractions, for which a treatment specific to each fraction is carried out subsequently. The atmospheric distillation enables the preparation, in a single step, of the various fractions desired (naphtha, gas-oil), thereby facilitating downstream hydrotreating adapted to each fraction and, consequently, the direct production of gas-oil or naphtha fuel base products which meet the various specifications. Fractionation after hydrotreating is therefore not necessary.

Owing to the high level of reduction in contaminants in the ebullating bed, the light fractions (naphtha and gas-oil) contain fewer contaminants and can therefore be treated in a fixed bed section, which generally has improved hydrogenation kinetics in relation to the ebullating bed. Similarly, the operating conditions can be milder because of the limited contaminants content. Providing a treatment for each fraction permits better operability in accordance with the desired products. Depending on the operating conditions selected (more or less stringent), it is possible to obtain either a fraction which can be conveyed to a fuels pool or a finished product which meets the specifications (sulphur content, smoke point, cetane, aromatics content, etc.) in force.

Upstream of the catalytic hydrotreating beds, the fixed bed hydrotreating sections preferably comprise specific guard beds for any arsenic compounds and silicon compounds contained within the diesel and/or naphtha fractions. The arsenic compounds, which have escaped the ebullating bed (because they are generally relatively volatile), are trapped in the guard beds, thus preventing poisoning of the downstream catalysts, and enabling production of highly arsenic-depleted fuel bases.

The atmospheric distillation also enables the concentration of the most resistant nitrogen compounds in the fraction which is heavier than the gas-oil fraction, which during step e) is hydrocracked. This step of hydrocracking permits to upgrade the fraction heavier than gas oil while producing products lighter and permits consequently to minimize the upgrading problems and economic outlets of this fraction.

DETAILED DESCRIPTION

The Hydrocarbon Feedstock

The hydrocarbon feedstock comprises at least one shale oil or a mixture of shale oils. The term “shale oil” is used here in its broadest sense and is intended to include any shale oil or a shale oil fraction which contains nitrogenous impurities. This includes crude shale oil, whether obtained by pyrolysis, by solvent extraction or by other means, or shale oil which has been filtered to remove the solids, or which has been treated by one or more solvents, chemical products, or other treatments, and which contains nitrogenous impurities. The term “shale oil” also comprises the shale oil fractions obtained by distillation or by another fractionating technique.

The shale oils used in the present invention generally have a Conradson carbon content of at least 0.1% by weight and generally at least 5% by weight, an asphaltenes content (IP143 standard/with C7) of at least 1%, often at least 2% by weight. Their sulphur content is generally at least 0.1%, often at least 1% and very often at least 2%, and even up to 4% or even 7% by weight. The amount of metals they contain is generally at least 5 ppm by weight, often at least 50 ppm by weight, and typically at least 100 ppm by weight or at least 200 ppm by weight. Their nitrogen content is generally at least 0.5%, often at least 1% and very often at least 2% by weight. Their arsenic content is generally greater than 1 ppm by weight, and up to 50 ppm by weight.

The method according to the present invention is intended for converting shale oils. Nevertheless, the feedstock may further comprise, in addition to the shale oil, other, synthetic liquid hydrocarbons, more particularly those which contain a substantial amount of cyclic organic nitrogen compounds. This includes oils derived from coal, oils obtained on the basis of heavy tars, bituminous sands, pyrolysis oils from ligneous residues such as wood residues, crudes obtained from biomass (“biocrudes”), vegetable oils and animal fats.

Other hydrocarbon feedstocks may also supplement the shale oil or the mixture of shale oils. The feedstocks are selected from the group consisting of oils derived from coal, oil derived from heavy tars and bituminous sands, vacuum distillates and direct distillation residues, vacuum distillates and unconverted residues obtained from conversion processes, such as, for example, those originating from distillation to the point of coke (coking), products obtained from fixed-bed hydroconversion of heavy fractions, products obtained from ebullating-bed processes for hydroconversion of heavy fractions, and oils deasphalted using solvents (for example, oils deasphalted with propane, with butane and with pentane, originating from the deasphalting of vacuum residues from direct distillation or of vacuum residues obtained from hydroconversion processes). The feedstocks may further comprise light cycle oil (LCO) of various origins, heavy cycle oil (HCO) of various origins, and also gas-oil cuts which originate from catalytic cracking and have in general a distillation range from about 150° C. to about 650° C. The feedstocks may also comprise aromatic extracts obtained in the manufacture of lubricating oils. The feedstocks may also be prepared and used in a mixture, in any proportions.

Hydrocarbons added to shale oil or to the mixture of shale oils may represent from 20% to 60% by weight of the total feedstock (shale oil or mixture of shale oils+added hydrocarbons), or from 10% to 90% by weight.

Hydroconversion

The feedstock containing the shale oil is first of all subjected to a hydroconverting step in an ebullating-bed [step a)]. By hydroconverting is meant reactions of hydrogenation, hydrotreating, hydrodesulphurization, hydrodenitrogenation, hydrodemetallation and hydrocracking.

The operation of the ebullating-bed catalytic reactor, including the recycling of the liquids from the reactor to the top through the agitated catalyst bed, is generally well known. Ebullating bed technologies use supported catalysts, generally in the form of extrudates having a diameter of generally of the order of 1 mm or less than 1 mm, for example greater than or equal to 0.7 mm. The catalysts remain inside the reactors and are not evacuated with the products. The catalytic activity can be held constant by virtue of on-line replacement (addition and withdrawal) of the catalyst. There is therefore no need to shut down the unit in order to change the spent catalyst, or to increase the reaction temperatures along the cycle in order to compensate for deactivation. Moreover, working with constant operating conditions enables consistent product qualities and consistent yields to be obtained throughout the cycle of the catalyst. Since the catalyst is held in agitation by substantial recycling of liquid, the head loss over the reactor remains low and constant, and the heat of reaction is rapidly averaged over the catalyst bed, which is therefore almost isothermal and does not require cooling via the injection of quenches. Implementing the hydroconversion in an ebullating bed obviates the problems of catalyst contamination that are associated with the deposits of impurities that are present naturally in shale oils.

The conditions in step a) of treating the feedstock in the presence of hydrogen are customarily conventional conditions for ebullating-bed hydroconversion of a liquid hydrocarbon fraction. It is customary to operate under a total pressure of 2 to 35 MPa, preferably of 10 to 20 MPa, at a temperature of 300° C. to 550° C. and often of 400° C. to 450° C. The hourly space velocity (HSV) and the hydrogen partial pressure are important factors, which are selected according to the characteristics of the product to be treated and to the desired conversion. The HSV is usually situated within a range from 0.2 h⁻¹ to 1.5 h⁻¹ and preferably from 0.4 h⁻¹ to 1 h⁻¹. The amount of hydrogen mixed with the feedstock is customarily from 50 to 5000 normal cubic metres (Nm³) per cubic metre (m³) of liquid feedstock, and usually from 100 to 1000 Nm³/m³, and preferably from 300 to 500 Nm³/m³.

This hydroconverting step a) may usually be implemented under the conditions of the T-STAR® process, as described for example in the article Heavy Oil Hydroprocessing, published by the AlChE, Mar. 19-23, 1995, Houston, Tex., paper number 42d. It may also be implemented under the conditions of the H-OIL® process, as described for example in the article published by NPRA, Annual Meeting, Mar. 16-18, 1997, J. J. Colyar and L. I. Wilson under the title The H-Oil® Process, A Worldwide Leader In Vacuum Residue Hydroprocessing.

The hydrogen required for the hydroconversion (and for the subsequent hydrotreating operations) may come from the steam reforming of hydrocarbons (methane) or else from the gas obtained from oil shales during the production of shale oils.

The catalyst in step a) is preferably a conventional granular hydroconversion catalyst, comprising, on an amorphous support, at least one metal or metal compound having a hydrodehydrogenating function. Generally speaking, a catalyst is used whose pore distribution is suitable for the treatment of feedstocks containing metals.

The hydrodehydrogenating function may be provided by at least one group VIII metal selected from the group consisting of nickel and/or cobalt, optionally in combination with at least one group VIB metal selected from the group consisting of molybdenum and/or tungsten. It is possible, for example, to use a catalyst comprising from 0.5% to 10% by weight of nickel and preferably from 1% to 5% by weight of nickel (expressed as nickel oxide, NiO) and from 1% to 30% by weight of molybdenum, preferably from 5% to 20% by weight of molybdenum (expressed as molybdenum oxide, MoO₃), on an amorphous inorganic support. The total amount of oxides of metals from groups VIB and VIII is often from 5% to 40% by weight and generally from 7% to 30% by weight. The weight ratio expressed as metal oxide between group VI metal (or metals) and group VIII metal (or metals) is generally from 20 to 1 and usually from 10 to 2.

The support of the catalyst will be selected, for example, from the group consisting of alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. This support may also include other compounds, for example oxides selected from the group consisting of boron oxide, zirconia, titanium oxide and phosphoric anhydride. It is usual to use an alumina support, and very often an alumina support doped with phosphorus and optionally with boron. In this case, the concentration of phosphoric anhydride, P₂O₅, is customarily less than about 20% by weight and usually less than about 10% by weight, and at least 0.001% by weight. The concentration of boron trioxide, B₂O₃, is customarily from approximately 0% to approximately 10% by weight. The alumina used is customarily a γ (gamma) or η (eta) alumina. This catalyst is usually in the form of an extrudate. The catalyst in step a) is preferably based on nickel and molybdenum, doped with phosphorus and supported on alumina. Use may be made, for example, of an HTS 458 catalyst sold by Axens.

Prior to the injection of the feedstock, the catalysts used in the method according to the present invention may undergo a sulphurizing treatment to convert at least partly the metallic species into sulphides before they are contacted with the feedstock to be treated. This activation treatment by sulphurization is well known to the skilled person and may be carried out by any method already described in the literature, either in situ, i.e. within the reactor, or ex situ.

The spent catalyst is partly replaced with fresh catalyst by withdrawal at the bottom of the reactor and introduction at the top of the reactor of fresh or new catalyst at regular intervals, for example by individual or quasi-continuous addition. It is possible, for example, to introduce fresh catalyst every day. The level of replacement of the spent catalyst by fresh catalyst may be, for example, from approximately 0.05 kg to approximately 10 kg per m³ of feedstock. This withdrawal and this replacement are carried out using devices which allow the continuous operation of this hydroconverting step. The unit customarily comprises a recirculation pump for maintaining the catalyst in an ebullating bed by continuous recycling of at least part of the liquid withdrawn at the top of the reactor and reinjected at the bottom of the reactor. It is also possible to convey the spent catalyst withdrawn from the reactor into a regenerating zone, in which the carbon and sulphur it contains are removed, and then to return this regenerated catalyst to the hydroconverting reactor of step a).

The operating conditions coupled with the catalytic activity allow feedstock conversion rates of possibly from 50% to 95%, preferably from 70% to 95%, to be obtained. The aforementioned degree of conversion is defined as the mass fraction of the feedstock at the start of the reaction section minus the mass fraction of the heavy fraction having a boiling point of more than 343° C. at the end of the reaction section, this figure being divided by the mass fraction of the feedstock at the start of the reaction section.

The technology of the ebullating bed allows treatment of feedstocks which are highly contaminated with metals, sediments and heteroatoms, without facing head loss problems or clogging problems, which are known when a fixed bed is used. The metals, such as nickel, vanadium, iron and arsenic, are largely removed from the feedstock by deposition on the catalysts during the reaction. The remaining (volatile) arsenic will be removed in the hydrotreating steps by specific guard beds. The sediments present in the shale oils are also removed via the replacement of the catalyst in the ebullating bed without disrupting the hydroconversion reactions. These steps also enable the removal, by hydrodenitrogenation, of the major part of the nitrogen, leaving only the most resistant nitrogen compounds.

The hydroconversion of step a) makes it possible to obtain an effluent having a nitrogen content that is greatly reduced relative to that of the feedstock, of the order of 3 times to 10 times less than in the feedstock.

Fractionation by Atmospheric Distillation

The effluent obtained in the hydroconverting step a) is conveyed at least partly, and preferably in its entirety, into a fractionating zone, from which a gaseous fraction, a naphtha fraction, a gas-oil fraction and a fraction heavier than the gas-oil fraction are recovered by atmospheric distillation.

The effluent obtained in step a) is preferably fractionated by atmospheric distillation into a gaseous fraction having a boiling point of less than 50° C., a naphtha fraction boiling at between about 50° C. and 150° C., a gas-oil fraction boiling at between about 150° C. and 370° C., and a fraction which is heavier than the gas-oil fraction and which boils generally at above 340° C., preferably at above 370° C.

The naphtha and diesel fractions are subsequently conveyed separately into hydrotreating sections. The fraction heavier than the gas oil fraction is conveyed into the hydrocracking section of step e).

The gaseous fraction contains gases (H₂, H₂S, NH₃, H₂O, CO₂, CO, C₁-C₄ hydrocarbons, etc.). It may advantageously undergo a purifying treatment for recovery of the hydrogen and its recycling into the hydroconverting section in step a) or into the hydrotreating sections in steps c) and d). Following purifying treatments, the C₃ and C₄ hydrocarbons may be used to form LPG (liquefied petroleum gas) products. The uncondensable gases (C₁-C₂) are generally used as internal fuel for the heating ovens of the hydroconversion and/or hydrotreating and/or hydrocracking reactors.

Hydrocracking

The process according to the invention comprises a hydrocracking step [step e)], in which at least one portion, preferably all, of the fraction heavier than gas oil obtained in step b), is sent into a hydrocracking section in the presence of hydrogen, in which said fraction heavier than gas oil is treated conventionally under conditions well known to those skilled in the art, in order to produce a second gaseous fraction, a second naphtha fraction, a second gas oil fraction and a second fraction heavier than gas oil, referred to as “unconverted oil”. The second naphtha fraction will be for example treated, at least partly, and often in its entirety, into the section for hydrotreating of step c). The second gas oil fraction will be, for example, at least partly, often entirely, sent to fuel pools and/or recycled at least partly, or even in its entirety, to the hydrotreating step d) The second fraction heavier than gas oil will be, for example, at least partly, or even in its entirety, sent to the heavy fuel oil pool and/or recycled at least partly, or even in its entirety, to the hydrocracking step e) and/or to the hydroconverting step a).

The hydrocracking effluents, obtained at the end of step e), may also be separated into a gas oil and lighter than gas oil fraction, and a second fraction heavier than gas oil. This gas oil and lighter than gas oil fraction is a mixture of a second gaseous fraction, a second naphtha fraction and a second gas oil fraction.

The gas oil and lighter than gas oil fraction may be sent, at least partly, and often in its entirety, to a fractionation zone of step b).

A brief description of hydrocracking can be found for example in ULLMANS ENCYCLOPEDIA OF INDUSTRIAL CHEMISTRY, VOLUME A18, 1991, page 71. A conventional catalyst or an assembly of conventional catalysts positioned on different fixed beds is customarily used. The catalysts used comprise combinations of metals supported on aluminas or zeolites. Examples of catalysts used within the context of the industrial operation of a hydrocracker include the catalysts Ni—Mo on alumina, Ni—Mo on zeolite, Ni—Mo and Ni—W on silica-alumina, Co—Mo on alumina and Co—Mo on zeolite. These catalysts may also contain, as a function of the desired properties, other metals chosen from transition metals and rare earth metals, in trace amounts or in relatively large proportions (from less than 1% by weight to 30% by weight relative to the total charge of metals) in metallic form or in oxide form.

The hydrocracking is carried out in a vertical reactor, generally in downflow mode. The feedstock is preheated in the presence of hydrogen before being introduced into the top of the reactor. A hydrogen makeup is introduced between each catalyst bed (quench gas) in order to reduce the temperature. This quench gas is then intimately mixed with the feedstock, usually in devices known as “quench boxes”.

The choice of the catalyst and of the operating conditions varies according to the products desired as a function of the feedstock treated. Hydrocracking units are usually operated at temperatures between 320° C. and 450° C., preferably between 350° C. and 400° C., with weight hourly space velocities between 0.3 and 7 h⁻¹, with a hydrogen/feedstock ratio between 300 and 1000 Nm³ of hydrogen/m³ of feedstock. Two types of hydrocracker are distinguished, as a function of their operating pressure: (1) MHC or mild hydrocracking units, which have operating pressures customarily between 8 and 15 MPa, more generally between 10 and 12 MPa, and (2) DHC or distillate hydrocracking units, which have operating pressures customarily between 12 and 20 MPa, more generally between 15 and 20 MPa.

Step e) of hydrocracking the fraction heavier than gas oil is carried out at a temperature between 350° C. and 450° C., preferably between 370° C. and 425° C., at a total pressure between 10 and 20 MPa, preferably between 15 and 18 MPa, at a weight hourly space velocity between 0.3 and 7 h⁻¹, preferably between 0.5 and 1.5 h⁻¹, and at a hydrogen/feedstock ratio between 100 and 5000 Nm³/m³, preferably between 1000 and 2000 Nm³/m³.

The use of an MHC unit, within the context of the invention, will produce effluents that are around 10% to 20% converted, sufficient for forming a synthetic crude oil, after mixing with the various naphtha and gas oil cuts resulting from the process. This synthetic crude will then be able to be sent to a conventional refinery. Alternatively, the use of a DHC unit, within the context of the invention, will produce effluents that are 80% to 90% converted, which should make it possible to direct the products more towards commercialization as bases for the manufacture of fuels.

Hydrotreating of the Naphtha Fraction and of the Gas-Oil Fraction

The naphtha and gas-oil fractions are subsequently subjected separately to fixed-bed hydrotreating [steps c) and d)]. Hydrotreating refers to reactions of hydrodesulphurization, hydrodenitrogenation and hydrodemetallation. The objective, depending on the operating conditions, which are selected so as to be more or less stringent, is to bring the various cuts up to the specifications (sulphur content, smoke point, cetane, aromatics content, etc.) or to produce a synthetic crude petroleum. Treating the naphtha fraction in one hydrotreating section and the gas-oil fraction in another hydrotreating section allows improved operability in terms of the operating conditions, so as to be able to bring each cut up to the required specifications with a maximum yield and in a single step per cut. In this way, fractionation after hydrotreating is unnecessary. The difference between the two hydrotreating sections is based more on differences in operating conditions than on the selection of the catalyst.

The fixed-bed hydrotreating sections preferably comprise, upstream of the catalytic hydrotreating beds, specific guard beds for the arsenic compounds (arsenic-containing compounds) and silicon compounds that are optionally present in the naphtha and/or diesel fractions. The arsenic-containing compounds which have escaped the ebullating bed (being generally relatively volatile) are trapped in the guard beds, thereby preventing the poisoning of downstream catalysts and enabling highly arsenic-depleted fuel bases to be obtained.

The guard beds which allow removal of arsenic and silicon from naphtha or gas-oil cuts are known to the skilled person. They comprise, for example, an absorbent material comprising nickel deposited on an appropriate support (silica, magnesia or alumina) as described in FR2617497, or else an absorbent material comprising copper on a support, as described in FR2762004. Mention may also be made of the guard beds sold by Axens: ACT 979, ACT 989, ACT 961, ACT 981.

The operating conditions in each hydrotreating section are adapted to the feedstock to be treated. The operating conditions for hydrotreating the naphtha fraction are generally gentler than those for the gas-oil fraction.

In the naphtha fraction hydrotreating step [step c)] it is customary to operate under an absolute pressure of 4 to 15 MPa, often of 10 to 13 MPa. The temperature during this step c) is customarily from 280° C. to 380° C., often from 300° C. to 350° C. This temperature is customarily adjusted in accordance with the desired level of hydrodesulphurization. The hourly space velocity (HSV) is usually situated within a range from 0.1 h⁻¹ to 5 h⁻¹, and preferably from 0.5 h⁻¹ to 1 h⁻¹. The amount of hydrogen mixed with the feedstock is customarily from 100 to 5000 normal cubic metres (Nm³) per cubic metre (m³) of liquid feedstock, and usually from 200 to 1000 Nm³/m³, and preferably from 300 to 500 Nm³/m³. It is useful to operate in the presence of hydrogen sulphide (for the sulphurizing of the catalyst), and the hydrogen sulphide partial pressure is customarily from 0.002 times to 0.1 times, and preferably from 0.005 times to 0.05 times, the total pressure.

In the gas-oil fraction hydrotreating step [step d)] it is customary to operate under an absolute pressure of 7 to 20 MPa, often of 10 to 15 MPa. The temperature during this step d) is customarily from 320° C. to 450° C., often from 340° C. to 400° C. This temperature is customarily adjusted depending on the desired level of hydrodesulphurization. The mass hourly velocity ((t of feedstock/h)/t of catalyst) is comprised between 0.1 and 1 h⁻¹. The hourly space velocity (HSV) is usually situated within a range from 0.2 h⁻¹ to 1 h⁻¹, and preferably from 0.3 h⁻¹ to 0.8 h⁻¹. The amount of hydrogen mixed into the feedstock is customarily from 100 to 5000 normal cubic metres (Nm³) per cubic metre (m³) of liquid feedstock, and usually from 200 to 1000 Nm³/m³, and preferably from 300 to 500 Nm³/m³. It is useful to operate in the presence of hydrogen sulphide, and the hydrogen sulphide partial pressure is customarily from 0.002 times to 0.1 times, and preferably from 0.005 times to 0.05 times, the total pressure.

In the hydrotreating sections, the ideal catalyst must have a high hydrogenating power, so as to produce thorough refining of the products, and to obtain a substantial lowering of the sulphur content and nitrogen content. In the preferred embodiment, the hydrotreating sections operate at relatively low temperature, which promotes thorough hydrogenation and a limitation on the coking of the catalyst. The use of a single catalyst or of two or more different catalysts, simultaneously or successively, in the hydrotreating sections would not depart from the scope of the present invention. The hydrotreating in steps c) and d) is customarily carried out industrially in one or more reactors with liquid downflow.

In the two hydrotreating sections [steps c) and d)], the same type of catalyst is used; the catalysts in each section may be identical or different. At least one fixed bed of conventional hydrotreating catalyst is used, comprising, on an amorphous support, at least one metal or metal compound having a hydrodehydrogenating function.

The hydrodehydrogenating function may be provided by at least one group VIII metal selected from the group consisting of nickel and/or cobalt, optionally in combination with at least one group VIB metal selected from the group consisting of molybdenum and/or tungsten. It is possible, for example, to use a catalyst comprising from 0.5% to 10% by weight of nickel and preferably from 1% to 5% by weight of nickel (expressed as nickel oxide, NiO) and from 1% to 30% by weight of molybdenum, preferably from 5% to 20% by weight of molybdenum (expressed as molybdenum oxide, MoO₃), on an amorphous inorganic support. The total amount of oxides of metals from groups VI and VIII is often from about 5% to about 40% by weight, and generally from about 7% to 30% by weight, and the weight ratio expressed in terms of metal oxide between metal (or metals) from group VIB to metal (or metals) from group VIII is in general from about 20 to about 1, and usually from about 10 to about 2.

The support is for example selected from the group consisting of alumina, silica, silica-aluminas, magnesia, clays and mixtures of at least two of these minerals. This support may also include other compounds, for example oxides selected from the group consisting of boron oxide, zirconia, titanium oxide and phosphoric anhydride. It is usual to use an alumina support, and very often an alumina support doped with phosphorus and optionally with boron. In this case, the concentration of phosphoric anhydride, P₂O₅, is customarily less than about 20% by weight and usually less than about 10% by weight and at least 0.001% by weight. The concentration of boron trioxide, B₂O₃, is customarily from approximately 0% to approximately 10% by weight. The alumina used is customarily a γ (gamma) or η (eta) alumina. This catalyst is usually in the form of beads or extrudates.

Prior to the injection of the feedstock, the catalysts used in the method according to the present invention are preferably subjected to a sulphurizing treatment enabling to convert at least partly the metallic species into sulphides before they are contacted with the feedstock to be treated. This activation treatment by sulphurization is well known to the skilled person and may be carried out by any method already described in the literature, either in situ, i.e. within the reactor, or ex situ.

The hydrotreating in step c) of the naphtha cut produces a cut containing not more than 1 ppm by weight of nitrogen, preferably not more than 0.5 ppm of nitrogen, and not more than 5 ppm by weight of sulphur, preferably not more than 0.5 ppm of sulphur.

The hydrotreating in step d) of the gas-oil cut produces a cut containing not more than 100 ppm of nitrogen, preferably not more than 20 ppm of nitrogen, and not more than 50 ppm of sulphur, preferably not more than 10 ppm of sulphur.

According to a penultimate aspect, the invention relates to the preparation of a synthetic crude by a method according to one of its preceding aspects.

According to a last aspect, the invention relates to a plant intended for treating a shale oil, employing a method according to one of its preceding aspects.

Such a plant comprises:

a section for hydroconverting in the presence of hydrogen, comprising an ebullating bed reactor operating in gas and liquid upflow mode and containing at least one supported hydroconverting catalyst,

a zone for fractionation by atmospheric distillation,

a first section for hydrotreating in the presence of hydrogen, comprising a fixed bed reactor containing at least one hydrotreating catalyst,

a second section for hydrotreating in the presence of hydrogen, comprising at least one fixed bed reactor containing at least one hydrotreating catalyst,

a section for hydrocracking in the presence of hydrogen.

These elements are arranged for the implementation of the method according to the invention.

Accordingly, for example:

the section for hydroconverting is connected to the zone for fractionation in order to feed this zone for fractionation with effluents issued from the section for hydroconverting,

a first duct (line) connects the zone for fractionation to the first section for hydrotreating, a second duct (line) connecting the zone for fractionation to the second section for hydrotreating, and a third duct (line) connects the zone for fractionation to the section for hydrocracking.

The plant may further comprise one or several recycle ducts for conveying different fractions to the section for hydroconverting, to the section for hydrocracking or to any of the first and second sections for hydrotreating.

FIG. 1 represents diagrammatically the method according to the present invention. FIG. 2 represents diagrammatically a variant of the method in which the separation of several cuts is performed in the same distillation unit.

According to FIG. 1, the feedstock comprising the shale oil (1) to be treated enters by the line (2) into the ebullating-bed hydroconverting section (3), in the presence of hydrogen (4), the hydrogen (4) being introduced by a line (5). The effluent from the ebullating bed hydroconverting section (3) is conveyed by the line (6) into an atmospheric distillation column (7), at the end of which a gaseous fraction (8), a naphtha fraction (9), a gas-oil fraction (10) and a fraction (11) heavier than the gas-oil fraction are recovered. The gaseous fraction (8), as well as a second gaseous fraction (26) containing hydrogen, may be purified (not shown) for recycling the hydrogen and reinjecting it (i) into the ebullating bed hydroconverting section (3) via the line (2) and/or (5), and/or (ii) into a hydrotreating sections (12) via a line (18) and/or (14), and/or (iii) into a hydrotreating sections (13) via a line (19) and/or (15), and/or (iv) into a hydrocracking sections (20) via a line (21) and/or (22). The naphtha fraction (9) is conveyed into the fixed bed hydrotreating section (12), at the end of which a naphtha fraction (16) depleted in impurities is recovered. The gas-oil fraction (10) is conveyed into the fixed bed hydrotreating section (13), at the end of which a gas-oil fraction (17) depleted in impurities is recovered. The two hydrotreating sections (12) and (13) are fed by hydrogen via the lines (14) and (15). The fraction (11) heavier than the gas-oil fraction is sent to the hydrocracking section (20) via the line (21). The hydrocracking effluents (23) are sent via a line (24) to a separation section (25) at the outlet of which the second gaseous fraction (26), a second naphtha fraction (27), a second gas oil fraction (28), and a second fraction heavier than gas oil (29) are recovered. The second naphtha fraction (27) may be sent, completely or partly, to the hydrotreatment section (12) via a line (30). The second gas oil fraction (28) is preferably sent to the gas oil pool or may be sent, completely or partly, to the hydrotreatment section (13) via a line (31). The second fraction heavier than gas oil (29) may be (i) drawn off, and/or (ii) sent back, completely or partly, to the hydrocracking section (20) via a line (32), and/or (iii) sent back, completely or partly, to the ebullated-bed hydroconversion section (3) via a line (33).

In FIG. 2, the hydroconverting, separating and hydrotreating steps (and reference symbols) are identical to those of FIG. 1 until the hydrocracking step, which present some differences.

The feedstock comprising the shale oil (1) to be treated enters by the line (2) into the ebullating-bed hydroconverting section (3), in the presence of hydrogen (4), the hydrogen (4) being introduced by a line (5). The effluent from the ebullating bed hydroconverting section (3) is conveyed by the line (6) into an atmospheric distillation column (7), at the end of which a gaseous fraction (8), a naphtha fraction (9), a gas-oil fraction (10) and a fraction (11) heavier than the gas-oil fraction are recovered. The gaseous fraction (8) containing hydrogen, may be purified (not shown) for recycling the hydrogen and reinjecting it (i) into the ebullating bed hydroconverting section (3) via the line (2) and/or (5), and/or (ii) into a hydrotreating sections (12) via a line (18) and/or (14), and/or (iii) into a hydrotreating sections (13) via a line (19) and/or (15), and/or (iv) into a hydrocracking sections (20) via a line (21) and/or (22). The naphtha fraction (9) is conveyed into the fixed bed hydrotreating section (12), at the end of which a naphtha fraction (16) depleted in impurities is recovered. The gas-oil fraction (10) is conveyed into the fixed bed hydrotreating section (13), at the end of which a gas-oil fraction (17) depleted in impurities is recovered. The two hydrotreating sections (12) and (13) are fed by hydrogen via the lines (14) and (15). The fraction (11) heavier than the gas-oil fraction is sent to the hydrocracking section (20) via the line (21). The hydrocracking effluents (23) are sent via a line (24) to a separation section (34) at the outlet of which, at the top, a mixture (35) comprising a second gaseous fraction, a second naphtha fraction and a second gas oil fraction (28) is recovered, and, at the bottom, a second fraction heavier than gas oil (29) is recovered. The mixture (35) is sent via a line (36) to the distillation column (7). The second fraction heavier than gas oil (29) may be (i) drawn off, and/or (ii) sent back, completely or partly, to the hydrocracking section (20) via a line (32), and/or (iii) sent back, completely or partly, to the ebullated-bed hydroconversion section (3) via a line (33).

EXAMPLE

A shale oil is treated that has the characteristics set out in Table 1.

TABLE 1 Characteristics of the shale oil feedstock Density 15/4 — 0.945 Hydrogen % by weight 10.9 Sulphur % by weight 1.9 Nitrogen % by weight 0.8 Oxygen % by weight 1.8 Asphaltenes % by weight 1.8 Conradson carbon % by weight 3.6 Metals ppm 236

The shale oil is treated in an ebullating bed reactor containing the commercial catalyst HOC 458 from Axens. The operating conditions are as follows:

-   -   Temperature in the reactor: 435° C.     -   Pressure: 195 bar (19.5 MPa)     -   Hydrogen/feedstock ratio: 600 Nm³/m³     -   Overall HSV: 0.3 h⁻¹

The liquid products obtained from the reactor are fractionated by atmospheric distillation to give a naphtha fraction (C5⁺-150° C.), a gas-oil fraction (150-370° C.) and a residual fraction 370° C⁺, which forms the fraction heavier than gas oil

The naphtha fraction is subjected to fixed bed hydrotreating using an NiMo-on-alumina catalyst. The operating conditions are as follows:

-   -   Temperature in the reactor: 320° C.     -   Pressure: 50 bar (5 MPa)     -   Hydrogen/feedstock ratio: 400 Nm³/m³     -   Overall HSV: 1 h⁻¹

The gas-oil fraction is subjected to fixed bed hydrotreating using an NiMo-on-alumina catalyst. The operating conditions are as follows:

-   -   Temperature in the reactor: 350° C.     -   Pressure: 120 bar (12 MPa)     -   Hydrogen/feedstock ratio: 400 Nm³/m³     -   Overall HSV: 0.6 h⁻¹

The fraction heavier than gas oil is then subjected to a hydrocracking operation using catalysts containing NiMo on alumina, NiW on silica alumina and NiMo on zeolite. This preheated feedstock in the presence of hydrogen is introduced into the top of a vertical reactor containing 5 catalyst beds. The operating pressure is 16 MPa absolute, the temperature is 380° C., the hydrogen/feedstock ratio is 1200 Nm³/m³, and the HSV is 0.6 h⁻¹. A hydrogen makeup is introduced between each catalyst bed (quench gas) in order to reduce the temperature. This quench gas is intimately mixed with the feedstock in devices known as “quench boxes”.

The hydrocracked hydrocarbons are drawn off at the bottom of the reactor and are cooled. They are sent to a fractionation unit, from which are isolated, as overhead, the gases, at least one naphtha cut, at least one gas oil cut, and at least one cut heavier than gas oil, as bottoms.

Table 2 gives the properties of the various feedstocks in each step and also the yields obtained in the various units, and the overall yield. Hence it is observed that, starting from 100% by weight of shale oil, 93.9% by weight of products (LPG, naphtha, middle distillates) are obtained conforming to the commercial Euro V specifications.

TABLE 2 Refinery unit H-Oil_(DC) Hydrocracker Feedstock C5+ Shale oil Bottoms Bottoms Product ex H-Oil_(RC) ex H-Oil_(DC) Product yield relative to % by weight 16.0 shale oil feedstock Properties of the products density (d15/4) — 0.852 sulphur % by weight 0.05 Total nitrogen % by weight 0.25 Yield relative to each unit LPG % by weight 2.2 2.5 Naphtha % by weight 27.1 23.5 Middle distillate % by weight 50.7 61.0 Bottoms % by weight 16.0 15.0 % by weight Yield relative to shale oil % by weight LPG % by weight 2.2 0.4 Naphtha % by weight 27.1 3.8 Middle distillate % by weight 50.7 9.8 Bottoms % by weight 16.0 2.4 Total (LPG + naphtha + 80.0 13.9 middle distillate)/shale oil feedstock Total (LPG + naphtha + 93.9 middle distillate)/shale oil feedstock 

1. Method for converting a shale oil or a mixture of shale oils having a nitrogen content of at least 0.1%, comprising: a) the feedstock is conveyed into a section for hydroconverting in the presence of hydrogen, said section comprising at least one ebullating bed reactor operating in gas and liquid upflow mode and containing at least one supported hydroconversion catalyst, b) the effluent obtained in step a) is conveyed at least partly into a fractionating zone, from which, by atmospheric distillation, a gaseous fraction, a naphtha fraction, a gas-oil fraction and a fraction heavier than gas-oil are recovered, c) said naphtha fraction is treated at least partly in a first section for hydrotreating in the presence of hydrogen, said section comprising at least one fixed bed reactor containing at least one hydrotreating catalyst, d) said gas-oil fraction is treated at least partly in a second section for hydrotreating in the presence of hydrogen, said section comprising at least one fixed bed reactor containing at least one hydrotreating catalyst, and e) the fraction heavier than the gas-oil fraction is treated at least partly in a hydrocracking section in the presence of hydrogen.
 2. Method according to claim 1, wherein the hydrocracking effluents obtained at the end of step e) are fractionated into a second gaseous fraction, a second naphtha fraction, a second gas-oil fraction, and a second fraction which is heavier than gas-oil.
 3. Method according to claim 2, wherein the second naphtha fraction is treated, at least partly, in the hydrotreating section of step c).
 4. Method according to claim 2, wherein the second gas oil fraction is treated, at least partly, in the hydrotreating section of step d).
 5. Method according to claim 2, wherein the second fraction heavier than gas oil is treated, at least partly, in the hydroconverting section of step a).
 6. Method according to claim 1, wherein the hydrocracking effluents obtained at the end of step e) are separated into a gas oil fraction and a fraction which is lighter than gas oil and a fraction which is heavier than gas-oil.
 7. Method according to claim 6, wherein the second fraction heavier than gas oil is treated, at least partly, in the hydroconverting section of step a).
 8. Method according to claim 6, wherein the gas oil fraction and the fraction which is lighter than gas oil is conveyed, at least partly, in a fractionating zone of step b).
 9. Method according to claim 2, wherein the second fraction heavier than gas oil is treated, at least partly, in the hydrocracking section of step e).
 10. Method according to claim 1, wherein the effluent obtained in step a) is fractionated by atmospheric distillation into a gaseous fraction having a boiling point of less than 50° C., a naphtha fraction boiling at between about 50° C. and 150° C., a gas-oil fraction boiling at between about 150° C. and 370° C., and a fraction which is heavier than the gas-oil fraction and which boils at above 340° C.
 11. Method according to claim 1, wherein the fixed bed hydrotreating sections in steps c) and/or d) comprise, upstream of the catalytic hydrotreating beds, at least one specific guard bed for arsenic compounds and silicon compounds.
 12. Method according to claim 1, wherein hydroconverting step a) operates at a temperature of between 300° C. and 550° C., at a total pressure of between 2 and 35 MPa, at a mass hourly velocity ((t of feedstock/h)/t of catalyst) of between 0.2 and 1.5 h⁻¹ and at a hydrogen/feedstock ratio of between 50 and 5000 Nm³/m³.
 13. Method according to claim 1, wherein step c) of hydrotreating the naphtha fraction operates at a temperature of between 280° C. and 380° C., at a total pressure of between 4 and 15 MPa, at a mass hourly velocity ((t of feedstock/h)/t of catalyst) of between 0.1 h⁻¹ and 5 h⁻¹, and at a hydrogen/feedstock ratio of between 100 and 5000 Nm³/m³.
 14. Method according to claim 1, wherein step d) of hydrotreating the gas-oil fraction operates at a temperature of between 320° C. and 450° C., at a total pressure of between 7 and 20 MPa, at a mass hourly velocity ((t of feedstock/h)/t of catalyst) of between 0.1 and 1 h⁻¹, and at a hydrogen/feedstock ratio of between 100 and 5000 Nm³/m³.
 15. Method according to claim 1, wherein step e) of hydrocracking the fraction heavier than gas-oil operates at a temperature of between 350° C. and 450° C., at a total pressure of between 10 and 20 MPa, at a mass hourly velocity ((t of feedstock/h)/t of catalyst) of between 0.3 and 7 h⁻¹, and at a hydrogen/feedstock ratio of between 100 and 5000 Nm³/m³.
 16. Method according to claim 1, wherein the catalysts in hydroconverting step a), hydrotreating steps c) and d), hydrocracking step e) are independently selected from the group of catalysts comprising a group VIII metal selected from the group consisting of Ni and/or Co, optionally a group VIB metal selected from the group consisting of Mo and/or W, on an amorphous support selected from the group consisting of alumina, silica, silica-aluminas, magnesia, clays and their mixtures, or on a support comprising at least partly a zeolite material.
 17. Method according to claim 1, wherein the shale oil or the mixture of shale oils is supplemented with a hydrocarbon feedstock selected from the group consisting of oils derived from coal, oils obtained from heavy tars and bituminous sands, vacuum distillates, and residues of direct distillation, vacuum distillates and unconverted residues obtained from a residue conversion process, oils deasphalted with solvents, light cycle oils, heavy cycle oils, gas-oil cuts originating from catalytic cracking and having generally a distillation range from approximately 150° C. to approximately 650° C., aromatic extracts obtained in the manufacture of lubricating oils, pyrolysis oils of ligneous residues such as wood residues, crudes obtained from biomass (“biocrudes”), vegetable oils and animal fats or mixtures of such feedstocks.
 18. Synthetic crude obtained by a method according to claim
 1. 19. Plant for treating a shale oil, comprising: a section for hydroconverting in the presence of hydrogen, comprising an ebullating bed reactor operating in gas and liquid upflow mode and containing at least one supported hydroconverting catalyst, a zone for fractionation by atmospheric distillation, a first section for hydrotreating in the presence of hydrogen, comprising a fixed bed reactor containing at least one hydrotreating catalyst, a second section for hydrotreating in the presence of hydrogen, comprising at least one fixed bed reactor containing at least one hydrotreating catalyst, a section for hydrocracking in the presence of hydrogen, these elements being arranged for the implementation of the method according to claim
 1. 